“Lost and Unaccounted for” Fluids
The balance between what comes in, what is used by the business, and what goes out is referred to in the pipeline business as the “lost and unaccounted for” (LUAF) or system balance. Ideally, this is managed using the laws of physical science, but they can be a contractual matter. Controlling the system balance is a matter of identifying influences that create differences between inlet measurement and outlet measurement, and either eliminating them or reducing them to acceptable levels. For liquids, many of the factors affecting the uncertainty of liquid measurements in the oil and gas business are covered in detail in the API Manual of Petroleum Measurement Standards (MPMS). The factors in gas measurement are different; most unaccounted for gas today is caused by the limitations of flow measurement resulting from poor meter application, operation, and maintenance.
Keywords
“lost and unaccounted for” (LUAF); system balance; pipeline; gas; liquid; industry standard; measurement; API Manual of Petroleum Measurement Standards (MPMS); meter
Introduction
The report card for any business is the balance between what comes in, what is used by the business, and what goes out. This is referred to in the pipeline business as the “lost and unaccounted for” (LUAF) or system balance. In plant operation it is called the plant balance. In either case, the control of the cost of doing business and the profits earned are based on this report. It must be properly and continually monitored so that control is effected. Management must support the investment of time, money, and personnel if they want a meaningful report upon which to base business decisions.
Ideally, system balance/LUAF is managed using the laws of physical science. Physical science provides laws for conservation of mass and energy but not volume; not even volume normalized to a set of reference conditions. However, all too frequently, companies rely on contractual requirements for system balance/LUAF control. Contracts are an agreement between parties to provide a designated exchange (volume, energy, and/or mass) and they often rely on custody transfer measurement requirements for control. Custody transfer measurement requirements usually rely on industry standards that rarely address measurement operation, maintenance and volume/energy post-processing adjustment methodology. While industry standards and custody transfer requirements normally represent good measurement practice, they rarely provide sufficient controls for acceptable system balance/LUAF management. In addition, standards are focused on individual meter station exchanges. Thus combining multiple exchanges in order to form a system balance assessment can introduce differences if the exchanged material is not exactly the same, i.e., of the same relative density. Even though the standards attempt to account for these volumetric differences through pressure, temperature, and compressibility normalization, they fail to address differences in relative density.
This issue is more significant for differential head meters where a difference of 0.001 relative density units can represent a 0.1% or more difference in normalized (standard or reference) volume. One might attempt to avoid this issue by conducting an energy balance or LUAF assessment, but total energy is not measured directly. The industry arrives at total energy, E, through the product of total normalized volumetric measurement, Q, and energy per unit volume (E/Q), i.e., E=Q×(E/Q), thus continuing to experience the issue. Contracts do not always account for normalized volume adjustments, i.e., transmitter calibrations, device corrections, physical properties corrections unless they exceed a stated percentage of average daily rate. Industry standards have been known to “grandfather” prior existing equipment or methodologies. This may be acceptable for custody transfer since it is an agreement between parties, but failing to incorporate all adjustments and/or “grandfathering” can build in either greater uncertainty (less control) or bias in the system balance/LUAF level. System balance/LUAF management needs to rely on the best measurement practices, Physical Science Laws, for controls. This is the only methodology able to minimize system balance/LUAF levels.
Controlling system balance is a matter of identifying influences that create differences between inlet measurement and outlet measurement and either eliminating them or reducing them to acceptable levels. Successful system balance control requires that it be properly managed. There is no basis for accountability if managing system balance or LUAF is not an identifiable function within an organization with dedicated responsibilities for monitoring, identifying, and reporting LUAF issues. The best measurement practice controls for system balance/LUAF management address all of the following:
1. Selection of the correct metering device for the application;
2. Installation of the selected metering device so that it may achieve its potential;
3. Operation of the selected metering system so that it may achieve its potential;
4. Processing of the metering system information so that it may retain its potential;
5. Maintenance of the metering system information so that it may retain its potential.
Pursuing sources of “lost and unaccounted for” should be a regular and ongoing process within a company dedicated to managing its system balance. (Auditing, to be discussed in Chapter 17, is best done by company personnel not involved in running the system being audited, or by outside independent specialists.)
Much of what follows in this chapter has been discussed previously in this book. It is repeated here as it directly applies to “lost and unaccounted for” reports.
Liquid
Many of the factors affecting the uncertainty of liquid measurements in the oil and gas business are covered in detail in the API Manual of Petroleum Measurement Standards (MPMS). This contains standard procedures, equipment, terms, and petroleum fluid correction tables for the calculation of standard or net volume used in the transfer of petroleum liquids.
The MPMS is considered by many to be the most useful reference for liquid hydrocarbon custody transfer measurement. It represents the best industry practices. It is continually updated as more knowledge is gained. It is usually the criteria used in conducting liquid hydrocarbon measurement audits. Contracts refer to these standards, so when disputes or imbalances occur in the liquid measurement, the first check should be to make sure these requirements and practices are being followed.
Properly applied, the MPMS chapters ensure that both parties arrive at the same volumes and any disputes or losses are minimized.
Factors that can contribute to liquid volume differences include:
Evaporation losses and leaks are two unmeasured losses out of the system. They are estimated based on company or industry levels, but are usually not the major source of the balance problems.
Bookkeeping and accounting include all records feeding the measurement balance including:
All of these records should be reviewed for obvious errors or data not in line with the “normal” data for a specific station.
Full reviews of all stations, including design and installation, are required to ensure that all installed equipment conforms to the API standards.
Dynamic Metering
The meters most commonly used for dynamic measurement of petroleum liquids are the orifice, ultrasonic, turbine, displacement, and Coriolis types. They should be reviewed to ensure that they are the proper choice for a given station, based on the meter’s characteristics, operational requirements, and the physical properties of the liquids. Operating the meters beyond their capabilities, or with their established meter factors, may cause problems. Such parameters as viscosity, temperature, and pressure change must be reviewed. Specific questions that must be answered are:
Are the flows staying within the range of the meter being used?
Are the meters capable of measuring the flowing parameters of temperature, viscosity, density, contaminants in the liquids, and corrosive liquids?
Are the meters protected from unstable flows by proper use of air eliminators, surge tanks, and relief valves?
For liquids close to their vaporization points, is sufficient back pressure being maintained, and are records available to check the settings? Is a flow-conditioning device properly installed and checked to ensure it is clean?
Static Metering
This is usually some type of tank gauging or vehicle weighing system where the following data must be checked and verified:
Comparison of Dynamic and Static Metering
When two different types of measuring systems are used, the proponents of one type will question the capability of the other type. However, properly applied, both systems can achieve comparable uncertainties.
Tank measurement accuracy depends on the total volume in the tank. With a small volume in the tank, the percentage of error caused by the limitations of the level measurement is critical. Therefore, operations of the gauging, timing, and volumes present should be monitored carefully.
Dynamic meters should be proved on a regular basis. However, unacceptable changes in a meter’s performance and/or a prover’s function must be monitored by evaluating the magnitude and direction of the changes in the meter’s meter factor under similar operating conditions. Meter factor control charts are recommended for monitoring the meter’s performance and identifying any unacceptable changes.
Specific differences found to cause problems in the meter include:
Summary of Liquid Balance Studies
Determining why volumes vary in liquid measurement requires the commitment of people, time, and money. Are inventories correct? Do the volumes of the terminals and the pipelines agree? If not, then a complete review of the documentation, the meter stations, and the operating and calculation procedures must be undertaken. Corrections of variations found will normally answer measurement questions and lead to an acceptable balance.
Gas
At one time, significant amounts of gas were actually lost through leaks in pipelines. This was many years ago when cast iron pipelines with bell and spigot-type joints were used for low pressure manufactured-gas distribution. Because of the porosity of the cast iron and the lack of sealing of bell and spigot joints, leakage was significant. Allowances were made for this gas as an unmeasured loss. It was a part of the economic calculation of the pipeline operating costs.
However, with the conversion to natural gas, involving higher-pressure, higher-volume production and long-distance pipelines, leaks were found by the presence of discolored vegetation or by spotting gas leaks—primarily made noticeable because of high-velocity noise—when walking the lines.
Other than very small leaks such as valves and flanges, pinholes, intentional blowdowns, and unexpected line losses, most unaccounted for gas today is caused by the limitations of flow measurement resulting from poor meter application, operation, and maintenance. Under the best of circumstances, all flow measurement has uncertainties that prevent 100% accuracy being achieved. Thus, the challenge of controlling the lost and unaccounted for gas is always present to some degree.
Where are these measurement uncertainties? The principal concern is to determine whether there is a problem of significance or whether the balance results fall within “realistic expectation.” So what are realistic expectations? Two sources that help to define realistic expectations are: (1) an operating company’s past history of specific measurement balances; and (2) the experiences of similar operating companies’ balances.
Depending on system and flow measurement complexities, a realistic expectation can vary from ±0.25 to ±0.5% for large pipeline companies, and from ±3.0 to ±10% for production field balances. Distribution companies usually fall somewhere in the ±3.0 to ±20.0% limits. All unaccounted for gas is lost revenue, so there are economic reasons for finding the sources of the loss (considering costs versus savings). Estimated savings depend on identifying the sources of differences, which can be quite small and not always easily found.
The Meters and Fluids
As previously mentioned, a system balance review should include the type of meters installed, their location, their installation, and sizes and types including primary elements and associated readout equipment. Equally important are fluid properties and how they are being determined. From this information, an estimate of expected system uncertainty can be determined. The review should include operating ranges and maintenance history of each station with emphasis on the larger volume stations as potential sources of significant loss.
The meters themselves should be compared to the latest industry standards and procedures. Flow measurement is an evolving practice, particularly with new meters impacting system balances. Operational procedures and standards are updated continually as new knowledge is obtained on the various meters’ (old or new) performance and the means of reducing uncertainties. An example is the 2000 revision to AGA Report No. 3, Part 2, which revised the installation requirements in order to reduce measurement uncertainty. This kind of knowledge can be used to evaluate previously installed meters to see if there are advantages to rebuilding and improving large-volume meter stations.
To verify meter selection and system operation, the following data should be collected and analyzed.
Meter
Information Flow
Once a problem station is identified, complete examination of the station should be made including:
Meter and meter installation to check for compliance with industry and/or company standards;
Gas quality meets contractual requirements with no carryover of solids or liquids;
Inspection of meter tube, secondary (transducers) and tertiary equipment (computers) to confirm they meet standards followed by a thorough test report review; and
Maintenance procedures checked for recurring calibration problems that may require upgrading or change of the present equipment.
Other sources for review are the leakage determination programs and reports as well as possible theft.
Meter Data
Depending on the type of system employed (e.g., electronic or manual charts), flow information must be moved to a central office to complete the billing process. This handling and rehandling of data must be controlled at all points: in the field, the transmittal system, the office data system and the billing system. Checks and auditing, including integrity checks throughout the process, can confirm that information is being moved without degradation (Figure 15-1).
The Fluid
Fluid characteristics and their effects on meters must be reviewed. With production gases there are often problems in maintaining a single phase and getting a legitimate sample for determining the heat value and other properties. Pipeline quality gases that have been separated and dried do not have as many problems.
What is the Magnitude of Savings?
Some idea of savings can be obtained by evaluating one of the major factors—metering uncertainty.
A meter study should concentrate first on stations with higher volumes. Quite often 90% of the total flow through a system is being metered by as few as 10 to 20% of the meters.
A 0.1% additional uncertainty or bias on a station handling 500,000 Mcf/day is equal to $20,000 per day for gas that sells for $4 per Mcf. On the other hand, the same additional uncertainty on a volume of 50 Mcf/day is $2. The error in this reasoning occurs when there are enough 50 Mcf/day stations to equal a 500,000 Mcf/day station.
For larger additional uncertainties or biases—in the 5, 10 or 20% range—meters measuring smaller flows become proportionately more important. This approach allows a program to be planned that has the best chance of finding unaccounted for gas with sufficient economic significance.
The foregoing are the major sources of measurement differences that produce unaccounted for gas. These field problems have increased in recent years because:
Maintenance and testing (time and personnel) have been reduced with budget reductions.
Auditing of the whole measurement process has been reduced to a minimum, if it is conducted at all.
Management is reluctant to spend money unless they can be guaranteed a return on investment of some set percentage (e.g., 15 or 20%). Putting definitive numbers on flow measurement uncertainty is at best an estimate, but is usually less than these values.
A great deal of upper management’s experience does not include operations, and therefore they are ill equipped to understand flow measurement problems and how to solve them.
Most unaccounted for gas will be “found” in field measurement problems. The solution to the problems will involve short-term expenditure, but will result in long-term income.
It is a bit daunting, however, to convince management who are not looking beyond the short-term profit and loss report to make a long-term investment of time and money.
Flow measurement solutions have been known to the gas industry for 50 years, but the gas industry has changed. The company that wants to find its unaccounted for gas should go back to the basics of good measurement. There is no silver bullet; finding LUAF losses requires a lot of hard work. But it is work that will pay off in terms of increased income.
Summary of Gas Balance Studies
The procedures outlined above are not a “one time and forget it” process, but should be instituted as a continuing operating procedure with all company personnel dedicated to minimizing the problem. Flow measurement problems found should be corrected as soon as defined. The data integrity from origin to final billing must be followed, analyzed, and audited in as close to real time as possible so that the quantities of gas measured are correct and current. This corrects for errors with a minimum of time required to correct billings, and it minimizes the effects on a company’s profits.